This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Water injection and gas injection are routinely used in oil and gas production fields to replace voidage in order to maintain reservoir pressure. Often the water and gas are injected in the same injection well. If both are injected, the process often involves alternating water and gas injection service of the well. The alternating injection is often referred to as Water-Alternating-Gas, or WAG, injection. WAG injection is an effective process for maintaining reservoir pressure, and has in many cases increased production and recovery over dedicated water injection only wells and gas injection only wells. Further, the effectiveness of WAG injection can often be improved by minimizing the time period for water and gas injection in a given well. This may be achieved by simultaneously injecting water and gas in the well. This process is often referred to as Simultaneous Water and Gas, or SWAG, injection. SWAG injection can improve water and gas management and reduce the capital cost of the injection system.
Immiscible WAG injection has been effectively used to manage produced gas at the Kuparuk River Unit, boosting the field rate and recovery. In Champion, et al., “An Immiscible WAG (Water-Alternating-Gas) Injection Project in the Kuparuk River Unit,” 1989, it was shown that trapped gas would alter reservoir fluid mobilities and result in improved waterflood sweep efficiency. In Ma, et al., “Performance of Immiscible Water-Alternating-Gas (IWAG) Injection at the Kuparuk River Unit, North Slope, Alaska,” 1994, other benefits of such trapped gas were observed, such as higher production rates, reduced water handling costs, and increased pressure support.
SWAG injection was identified as an option that could reduce capital and operating costs and improve gas handling and oil recovery. In Attanucci, et al., “WAG Process Optimization in the Rangely Carbon Dioxide Miscible Flood”, 1993, improved gas handling and oil recovery were reported for SWAG injection at the Joffre Viking CO2 miscible flood and SWAG emulation at the Rangely CO2 miscible flood. Results of the mobility control test at Joffre Viking CO2 miscible flood indicated that simultaneous CO2 and water injection at water/CO2 ratios approaching 1 resulted in improved sweep compared with Water-Alternating-CO2 injection and continuous CO2 injection. Dual tubing strings were installed in the SWAG well. In addition, results of the WAG process optimization at the Rangely CO2 miscible flood indicated that reducing half-cycle lengths had the potential to increase the efficiency of the CO2 recovery process, add incremental reserves, and improve lift efficiencies, resulting in reduced operating costs. For optimal net present values, the average half-cycles were reduced from 1.5% to 0.25% hydrocarbon pore volume (HCPV).
In Ma, et al., “Simultaneous Water and Gas Injection Pilot at the Kuparuk River Field, Reservoir Impact”, 1995, the application of the SWAG process to the Kuparuk River Unit was evaluated using reservoir simulations. Simulation analyses were conducted to estimate the benefits of SWAG injection at a water to gas ratio of 10:1, corresponding to a gas-liquid ratio of 120 SCF per barrel. The 10:1 SWAG ratio was designed to achieve dispersed bubble flow. Sensitivity studies were also made to evaluate the benefits of a 1:1 SWAG ratio and a 1:1 Immiscible Water-Alternating Gas, or IWAG, ratio. The 10:1 SWAG case yielded an incremental oil recovery of 2.2% of the original oil-in-place (OOIP) over waterflood. This corresponded to a total gas slug of only 10% HCPV. SWAG injection resulted in depressed watercuts. The normal IWAG injection at 1:1 water to gas ratio yielded an incremental recovery of 4.5% OOIP. SWAG injection at 1:1 water to gas ratio yielded the highest incremental recovery of 5.0% OOIP.
In Van Ligen, et al., “WAG Injection to Reduce Capillary Entrapment in Small-Scale Heterogeneities”, 1996, an experimental study of SWAG injection was performed as a means to reduce the capillary entrapment of oil. Six experiments were conducted using three heterogeneity geometries. The results indicated that SWAG injection results in significantly higher displacement efficiency than water injection.
In Quale, et al., “SWAG Injection on the Siri Field—An Optimized Injection System for Less Cost”, 2000, and Berge, et al., “SWAG Injectivity Behavior Base on Siri Field Data”, 2002, the successful implementation of SWAG at the Siri Field in the North Sea was reported. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The total injection volume desired for voidage replacement is achieved with a simplified injection system, fewer wells and reduced gas recompression pressure requirements. In addition, SWAG injection is estimated to yield an incremental recovery of 6% over water injection.
Conventionally, WAG systems have been used for pressure maintenance in a reservoir. Typically, for a subsea operation, this involves bringing a multiphase flow production stream to a topsides facility, separating and recompressing the gas, and then sending the gas back to a subsea reservoir. In addition, according to current SWAG injection systems, a multiphase flow production stream is brought to a topsides facility. The gas is then separated from the multiphase flow production stream, recompressed, and sent back through an injection line to the reservoir. However, bringing the multiphase flow production stream all the way to shore or to a topside facility often results in high capital and operating expenditures.